Renewable Electricity Futures Study-4

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Renewable Electricity

Futures Study

Bulk Electric Power Systems:Operations and TransmissionPlanning

Volume 4 of 4

Volume 2

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Volume 3

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Volume 1

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Volume 4

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NREL is a national laboratory o the U.S. Department o Energy,

Ofce o Energy Efciency and Renewable Energy, operated by the Alliance or Sustainable Energy, LLC.
http://www.nrel.gov/docs/fy12osti/52409-2.pdfhttp://www.nrel.gov/docs/fy12osti/52409-2.pdfhttp://www.nrel.gov/docs/fy12osti/52409-3.pdfhttp://www.nrel.gov/docs/fy12osti/52409-3.pdfhttp://www.nrel.gov/docs/fy12osti/52409-1.pdfhttp://www.nrel.gov/docs/fy12osti/52409-1.pdfhttp://www.nrel.gov/docs/fy12osti/52409-1.pdfhttp://www.nrel.gov/docs/fy12osti/52409-2.pdfhttp://www.nrel.gov/docs/fy12osti/52409-3.pdf


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Renewable Electricity Futures Study

Edited By

Hand, M.M.National Renewable

Energy Laboratory

Baldwin, S.U.S. Department of

Energy

DeMeo, E.Renewable Energy

Consulting Services, Inc.

Reilly, J.M.Massachusetts Institute ofTechnology

Mai, T.National RenewableEnergy Laboratory

Arent, D.Joint Institute for StrategicEnergy Analysis

Porro, G.National RenewableEnergy Laboratory

Meshek, M.National RenewableEnergy Laboratory

Sandor, D.National RenewableEnergy Laboratory

Suggested CitationsRenewable Electricity Futures Study (Entire Report)National Renewable Energy Laboratory. (2012). Renewable Electricity Futures Study. Hand, M.M.;

Baldwin, S.; DeMeo, E.; Reilly, J.M.; Mai, T.; Arent, D.; Porro, G.; Meshek, M.; Sandor, D. eds. 4 vols.NREL/TP-6A20-52409. Golden, CO: National Renewable Energy Laboratory.http://www.nrel.gov/analysis/re_futures/.

Volume 4: Bulk Electric Power Systems: Operations and Transmission PlanningMilligan, M.; Ela, E.; Hein, J.; Schneider, T.; Brinkman, G.; Denholm, P. (2012). Exploration of High-Penetration Renewable Electricity Futures. Vol. 4 of Renewable Electricity Futures Study.NREL/TP-6A20-52409-4. Golden, CO: National Renewable Energy Laboratory.
http://www.nrel.gov/analysis/re_futures/http://www.nrel.gov/analysis/re_futures/http://www.nrel.gov/analysis/re_futures/


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Renewable ElectricityFutures Study

Volume 4: ExplorationBulk Electric PowerSystems: Operationsand TransmissionPlanning

Michael Milligan,1 Erik Ela,1

Jeff Hein,2 Thomas Schneider,1

Gregory Brinkman,1 Paul Denholm1

1 National Renewable Energy Laboratory2National Renewable Energy Laboratory,formerly


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NOTICE

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Renewable Electricity Futures StudyVolume 4: Bulk Electric Power SystemsOperations and Transmission Planning

iii

Perspective

The Renewable Electricity Futures Study (RE Futures) provides an analysis of the gridintegration opportunities, challenges, and implications of high levels of renewable electricitygeneration for the U.S. electric system. The study is not a market or policy assessment. Rather,

RE Futures examines renewable energy resources and many technical issues related to theoperability of the U.S. electricity grid, and provides initial answers to important questions aboutthe integration of high penetrations of renewable electricity technologies from a nationalperspective. RE Futures results indicate that a future U.S. electricity system that is largelypowered by renewable sources is possible and that further work is warranted to investigate thisclean generation pathway. The central conclusion of the analysis is that renewable electricitygeneration from technologies that are commercially available today, in combination with a moreflexible electric system, is more than adequate to supply 80% of total U.S. electricity generationin 2050 while meeting electricity demand on an hourly basis in every region of the United States.

The renewable technologies explored in this study are components of a diverse set of clean

energy solutions that also includes nuclear, efficient natural gas, clean coal, and energyefficiency. Understanding all of these technology pathways and their potential contributions tothe future U.S. electric power system can inform the development of integrated portfolioscenarios. RE Futures focuses on the extent to which U.S. electricity needs can be supplied byrenewable energy sources, including biomass, geothermal, hydropower, solar, and wind.

The study explores grid integration issues using models with unprecedented geographic and timeresolution for the contiguous United States. The analysis (1) assesses a variety of scenarios withprescribed levels of renewable electricity generation in 2050, from 30% to 90%, with a focus on80% (with nearly 50% from variable wind and solar photovoltaic generation); (2) identifies thecharacteristics of a U.S. electricity system that would be needed to accommodate such levels;and (3) describes some of the associated challenges and implications of realizing such a future.In addition to the central conclusion noted above, RE Futures finds that increased electric systemflexibility, needed to enable electricity supply-demand balance with high levels of renewablegeneration, can come from a portfolio of supply- and demand-side options, including flexibleconventional generation, grid storage, new transmission, more responsive loads, and changes inpower system operations. The analysis also finds that the abundance and diversity of U.S.renewable energy resources can support multiple combinations of renewable technologies thatresult in deep reductions in electric sector greenhouse gas emissions and water use. The studyfinds that the direct incremental cost associated with high renewable generation is comparable topublished cost estimates of other clean energy scenarios. Of the sensitivities examined,improvement in the cost and performance of renewable technologies is the most impactful leverfor reducing this incremental cost. Assumptions reflecting the extent of this improvement are

based on incremental or evolutionary improvements to currently commercial technologies and donot reflect U.S. Department of Energy activities to further lower renewable technology costs sothat they achieve parity with conventional technologies.


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RE Futures is an initial analysis of scenarios for high levels of renewable electricity in the UnitedStates; additional research is needed to comprehensively investigate other facets of highrenewable or other clean energy futures in the U.S. power system. First, this study focuses onrenewable-specific technology pathways and does not explore the full portfolio of cleantechnologies that could contribute to future electricity supply. Second, the analysis does not

attempt a full reliability analysis of the power system that includes addressing sub-hourly,transient, and distribution system requirements. Third, although RE Futures describes the systemcharacteristics needed to accommodate high levels of renewable generation, it does not addressthe institutional, market, and regulatory changes that may be needed to facilitate such atransformation. Fourth, a full cost-benefit analysis was not conducted to comprehensivelyevaluate the relative impacts of renewable and non-renewable electricity generation options.

Lastly, as a long-term analysis, uncertainties associated with assumptions and data, along withlimitations of the modeling capabilities, contribute to significant uncertainty in the implicationsreported. Most of the scenario assessment was conducted in 2010 with assumptions concerningtechnology cost and performance and fossil energy prices generally based on data available in2009 and early 2010. Significant changes in electricity and related markets have already occurredsince the analysis was conducted, and the implications of these changes may not have been fullyreflected in the study assumptions and results. For example, both the rapid development ofdomestic unconventional natural gas resources that has contributed to historically low natural gasprices, and the significant price declines for some renewable technologies (e.g., photovoltaics)since 2010, were not reflected in the study assumptions.

Nonetheless, as the most comprehensive analysis of U.S. high-penetration renewable electricityconducted to date, this study can inform broader discussion of the evolution of the electricsystem and electricity markets toward clean systems.

The RE Futures team was made up of experts in the fields of renewable technologies, grid

integration, and end-use demand. The team included leadership from a core team with membersfrom the National Renewable Energy Laboratory (NREL) and the Massachusetts Institute ofTechnology (MIT), and subject matter experts from U.S. Department of Energy (DOE) nationallaboratories, including NREL, Idaho National Laboratory (INL), Lawrence Berkeley NationalLaboratory (LBNL), Oak Ridge National Laboratory (ORNL), Pacific Northwest NationalLaboratory (PNNL), and Sandia National Laboratories (SNL), as well as Black & Veatch andother utility, industry, university, public sector, and non-profit participants. Over the course ofthe project, an executive steering committee provided input from multiple perspectives tosupport study balance and objectivity.

RE Futures is documented in four volumes of a single report: Volume 1 describes the analysis

approach and models, along with the key results and insights; Volume 2 describes the renewablegeneration and storage technologies included in the study; Volume 3 presents end-use demandand energy efficiency assumptions; and this volumeVolume 4discusses operational andinstitutional challenges of integrating high levels of renewable energy into the electric grid.


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v

List of Acronyms

AC alternating current

AGC automatic generation control

BA balancing area

Btu British thermal unit

CAISO California ISO

CREZ Competitive Renewable Energy Zones

CSP concentrating solar thermal power plants

DC direct current

EIA U.S. Energy Information Administration

ELCC effective load-carrying capability

EPACT 1992 Energy Policy Act of 1992

ERCOT Electric Reliability Council of Texas

EWITS Eastern Wind Integration and Transmission Study

FERC Federal Energy Regulatory Commission

FOA Funding Opportunity Announcement

HVDC high-voltage direct current

Hz Hertz

ISO Independent System Operator

kW kilowatt

kWh kilowatt-hour

LMPs locational marginal prices

LOLE loss-of-load expectation

LOLP loss-of-load probability

MISO Midwest ISO

MW megawatt

MWh megawatt-hour

NERC North American Electric Reliability Corporation

NYISO New York ISO

PJM Pennsylvania, New Jersey, and Maryland RTO

PV photovoltaic

RE Futures Renewable Electricity Futures StudyReEDS Regional Energy Deployment Systems

RSG reserve-sharing group

RTO Regional Transmission Organization

WWSIS Western Wind and Solar Integration Study


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Table of Contents

Perspective ................................................................................................................................................. iiiList of Acronyms ......................................................................................................................................... vIntroduction .............................................................................................................................................. viiiChapter 22. The North American Electric Power System: The Grid ................................................. 22-1

22.1 Balancing Authorities ................................................................................................. 22-222.2 Regional Entities ......................................................................................................... 22-222.3 Utilities and Power Pools ............................................................................................ 22-422.4 ISOs, RTOs, and other Transmission Organizations .................................................. 22-4

Chapter 23. Utility System Planning .................................................................................................... 23-1Chapter 24. Grid Reliability ................................................................................................................... 24-1

24.1 Planning Reserves (Reserve Margin).......................................................................... 24-3Chapter 25. Power System Operations ................................................................................................ 25-1

25.1 Security-Constrained Unit Commitment .................................................................... 25-225.2 Economic Dispatch and Load Following .................................................................... 25-425.3 Frequency Response and Control ............................................................................... 25-4

Chapter 26. Transmission Technology and Institutional Issues....................................................... 26-126.1 Transmission Technology ........................................................................................... 26-126.2 Transmission and Institutional Issues ......................................................................... 26-6

Chapter 27. Power System Considerations for High Levels of Renewable Generation ................. 27-127.1 Technical Challenge of Variable Generation .............................................................. 27-327.2 Institutional Challenges of Variable Generation ......................................................... 27-427.3 Impact of Variable Generation on Power System Operations .................................... 27-527.4 Impact of Variable Generation on Transmission ...................................................... 27-22

Chapter 28. Modeling of System Expansion and Operations for RE Futures Scenarios ............... 28-128.1 The Regional Energy Deployment Systems Model .................................................... 28-128.2 The GridView Model .................................................................................................. 28-4

Summary and Conclusions ................................................................................................................... 29-1References .............................................................................................................................. References-1


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List of Figures

Figure 22-1. North American Electric Reliability Corporation synchronous interconnectionsand regional entities ....................................................................................................... 22-3

Figure 22-2. Independent system operators and regional transmission organizations of North

America .......................................................................................................................... 22-5Figure 24-1. Examples of reliability curves to illustrate effective load-carrying

capability ........................................................................................................................ 24-4Figure 25-1. Timescales for power system operation .......................................................... 25-1Figure 25-2. Example conventional generator contingency event and response ................. 25-3Figure 26-1. Comparison of costs to deliver 6,000 MW over various distances and voltages

at 75% utilization ........................................................................................................... 26-3Figure 26-2. Comparison of general right-of-way requirements for various transmission

types ............................................................................................................................... 26-4Figure 27-1. Impact of high level of wind generation ......................................................... 27-6Figure 27-2. Data from Western Wind and Solar Integration Study: Per-unit variability of

wind power for four transmission zones ........................................................................ 27-7Figure 27-3. Data from Eastern Wind Integration and Transmission Study: Normalized10-minute variability for five regional groups ............................................................... 27-8

Figure 27-4. Wind ramp event, Electric Reliability Council of Texas, February 26,2008.............................................................................................................................. 27-12

Figure 27-5. Simplified example for load alone ................................................................ 27-13Figure 27-6. Elimination of hourly ramping ...................................................................... 27-18

List of Tables

Table 26-1. Ongoing Ultra-High-Voltage Projects in China, 2009 ....................................... 26-5

List of Text Boxes

Text Box 27-1. Locational Marginal Prices ......................................................................... 27-21


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viii

Introduction

Today, the U.S. electric grid faces a number of technical and institutional challenges, includingintegrated management of both loads and generation, supporting wholesale electricity markets,facilitating customer participation in the marketplace, reducing carbon emissions, and reducing

dependence on petroleum by electrifying transportation. Technical issues associated with thesechanges challenge legacy grid planning and operational practices, and they will likely requiresubstantial, or perhaps even transformational, changes for the U.S. grid to respond effectively.The rapid deployment of renewable electricityparticularly the addition of 40,000 MW of windgenerationto the U.S. grid over the last 10 years is one driver of change. The RenewableElectricity Futures Study (RE Futures) examines the implications and challenges of renewableelectricity generation levelsfrom 30% up to 90% of all U.S. electricity generation fromrenewable technologiesin 2050. Additional sensitivity cases are focused on an 80%-by-2050scenario. At this 80% renewable generation level, variable generation from wind and solarresources accounts for almost 50% of the total generation. At such high levels of renewableelectricity generation, the unique characteristics of some renewable resources, specifically

resource geographical distribution, and variability and uncertainty in output, pose challenges tothe operability of the U.S. electric system.

RE Futures is documented in four volumes. Volume 1 describes the analysis approach andmodels, along with the key results and insights. Volume 2 describes the renewable generationand storage technologies included in the study. Volume 3 presents end-use demand and energyefficiency assumptions. Volume 4 (this volume) focuses on the role of variable renewablegeneration in creating challenges to the planning and operations of power systems and theexpansion of transmission to deliver electricity from remote resources to load centers. Thetechnical and institutional changes to power systems that respond to these challenges are, inmany cases, underway, driven by the economic benefits of adopting more moderncommunication, information, and computation technologies that offer significant operational costsavings and improved asset utilization. While this volume provides background information andnumerous references, the reader is referred to the literature for more complete tutorials.

1

This volume also provides an overview of todays electric power system (the grid), includinghow planning and operations are carried out to ensure reliability. It then explores the challengesto the grid posed by high levels of variable renewable generation and some changes that areexpected to occur in response to these challenges. Finally, this volume concludes with adiscussion of the capacity expansion and production cost models used in RE Futures and howthey represent the operational issues discussed earlier.

1 For a full tutorial on the basics of power systems, see Casazza and Delea (2010) and Brown and Sedano (2004).


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22-1

Chapter 22. The North American Electric Power System: The Grid

The electric power system is the infrastructure that converts fuel and energy resources intoelectric power (thus generating electricity) and carries and manages that electric power fromwhere it is generated to where it is used.

2It is a system of systems that comprises physical

networks that include fuel and resources; power plants of many different varieties; electrictransmission and distribution line networks and measurement; information and control systems;and virtual networks of money, business relationships, and regulation. Achieving balance amongall of these elements is a fundamental challenge for the planning, engineering, and operation ofthe overall system because of the variability and uncertainty of load and unexpected equipmentfailures that affect the generation and delivery of electricity. The system of systems is looselyreferred to here as the grid.

The major physical elements of the grid are generation, transmission, distribution, and load.Generation is the collection of power plants electrically connected to the grid and ranging in sizefrom very small, distributed units3 to central stations rated at over 1,000 MW (Casazza and

Delea 2010). Transmission is the collection of networked high-voltage lines (above 100 kV) thattie generation to load centers. High-voltage lines also connect utilities to one another, reducecosts through sharing of resources, and provide enhanced reliability in case of events such as theloss of a large generator. The high-voltage transmission system also enables the wholesalemarketplace for electricity. In general, the bulk or wholesale system refers to the network ofinterconnected generation and transmission lines, while the distribution system refers to thelower-voltage generally radial lines that deliver electricity to the final customer. The loadcreated by the electrical equipment on the customers side of the meteris electrically part ofthe overall power system and affects its operation; load completes the system. The largestindustrial and commercial customers may be served by transmission directly; the rest are servedby the lower-voltage distribution system.

When the development of electric power began more than 130 years ago, generating plants wereisolated and served dedicated customers. Over the next several decades, utilities began linkingmultiple generating plants into isolated systems. By the mid-1920s, it was clear that connectionsamong utility systems could provide additional reliability and savings with fewer cumulativeresources. The connection of neighboring utilities provided access to generation reserves in timesof equipment failure, unexpected demand, or routine maintenance, as well as improvedeconomics through reserve sharing and access to diverse and lower-cost energy resources. TheU.S. grid today is the result of a complex web of legacy designs developed from the early 1920sto the present. By the 1980s, the North American electric system had been transformed fromisolated utilities to an interregional grid spanning the continent.

The three large areas or interconnections that operate as synchronous4 interconnected systemsin the contiguous United States, Canada, and a small portion of Mexico are the Western

2 Electric power is in units of watts and electricity is in units of watt-hours; they are often used interchangeably.3 Many small distributed generators or small power units are installed at hospitals, fire stations, and other criticalfacilities to provide power in case of emergencies or failure of the grid resulting in an interruption of the flow ofelectricity. These standby or emergency backup systems are not normally electrically connected to the grid. With theaddition of proper control and switching systems, these units could be connected.4 All of the generators are operating at the same synchronous frequency of 60 Hertz, producing AC electricity.


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22-2

Interconnection, the Eastern Interconnection, and Electric Reliability Council of Texas (ERCOT)in Texas (Figure 22-1). The three interconnections are connected by a small number of DCconnections with very limited transfer capacity.5 Quebec is also connected to the United Statesand neighboring Canada with HVDC ties. Alaska and Hawaii have their own systems.

Many entitiesbalancing authorities, regional entities, utilities, power pools, independentsystem operators (ISOs), regional transmission organizations (RTOs), and other transmissionorganizationsare involved in running the grid today. At the federal level, the Federal EnergyRegulatory Commission (FERC) has regulatory authority over interstate sale of electricity andthe operation of regional markets. The North American Electric Reliability Corporation (NERC)has the responsibility, under FERC authority, for power system reliability, operating, andplanning standards in the United States, and coordinates with Canada. Every utility in the UnitedStates and Canada participates in the NERC reliability assessments to ensure that thetransmission system meets standards and will perform reliably. Most criteria for planning oftransmission are based on the NERC standards.

22.1 Balancing AuthoritiesFrom a system perspective, the balancing authority6 is the critical management element. Asdefined by NERC, the balancing authority (formerly called control area) is the responsible entityfor ensuring the electrical balance between load and generation; the balancing authoritymaintains frequency and ties to neighboring balancing authorities. Within the balancingauthoritys area, generation schedules are established to meet the changing demand. Deviationsfrom this balance result in changes to system frequency and net imports from, or exports to,neighboring balancing authorities. Generally, these imports and exports are scheduled inadvance, but deviations from the schedule are common, with limitations on how often thesedeviations can occur and persist.

22.2 Regional Entities

Eight regional entities provide a mechanism to address the differences across the regions inNorth America (see Figure 22-1). NERC works with the regional entities to improve thereliability of the bulk power system while acknowledging the differences between regions.Membership of the regional entities comes from all segments of the electric industry andaccounts for virtually all the electricity supplied in the United States, Canada, and a portion ofBaja California Norte, Mexico.

5 The reason that back-to-back HVDC ties are used rather than simpler AC connections is a consequence of somerather technical aspects of the operation of large AC power systems as well as certain aspects of the history ofdevelopment of transmission.6 According to NERC (n.d.), the balancing authority is, [o]ne of the regional functions contributing to the reliableplanning and operation of the bulk power system. The Balancing Authority integrates resource plans ahead of time,and maintains in real time the balance of electricity resources and electricity demand.


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22-3

Figure 22-1. North American Electric Reliability Corporation synchronous interconnectionsand regional entities

Eastern Interconnection: FRCC = Florida Reliability Coordinating Council

MRO = Midwest Reliability Organization

NPCC = Northeast Power Coordinating CouncilRFC = Reliability First Corporation (PJM)

SERC = Southeastern Electric Reliability Council

SPP = Southwest Power Pool

Western Interconnection: WECC = Western Electricity Coordinating Council

Texas Interconnection: TRE = Texas Regional Entity or ERCOT (Electric Reliability Council ofTexas)

Source: NERC


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22.3 Utilities and Power PoolsFrom the approval of the Federal Power Act in 1935 to the start of restructuring followingenactment of the Energy Policy Act of 1992, the grid was designed to provide reliable electricpower at minimum costs to customers and was regulated to ensure just and reasonable rates.The dominant business model for U.S. electric power during this period was that of a vertically

integrated, investor-owned, and state-regulated local utility monopoly.

7

In addition to theinvestor-owned utilities, there were (and still are) federal, state, and municipal utilities, and ruralcooperatives, totaling more than 3,000 load-serving entities. In a few regionsPennsylvania,New Jersey, and Maryland (PJM); New England; and New Yorkutilities are organized intopower pools to share savings through cooperation with neighbors. In general, utilities thatcontrolled generation also owned and operated the transmission systems. Local utility companiesand their customers benefited from the economic exchange of electric energy in power poolsacross regional networks.

22.4 ISOs, RTOs, and other Transmission OrganizationsThe Energy Policy Act of 1992 mandated open access to the transmission system. Further accessto the transmission system resulted from FERC Orders 888/889 with the creation of ISOs andsubsequently in Order 2000 with the creation of RTOs to satisfy the requirement of providingnon-discriminatory access to the transmission system. With Order No. 2000, FERC encouragedthe voluntary formation of RTOs to operate the transmission grid on a regional basis throughoutthe United States. Order No. 2000 delineated 12 characteristics and functions that an entity mustsatisfy to become an RTO (Figure 22-2). In the Eastern Interconnection, the development ofRTOs and organized wholesale power markets has transferred a large part of the resourceprocurement function from states to FERC jurisdiction. The operation and responsibilities ofISOs and RTOs are very similar.8

Regions without ISOs and RTOs (such as the Pacific Northwest and the majority of Southeasternstates) must conform to FERCs open access mandate; the power exchange among utilities is

mostly facilitated through bilateral contracts and power purchase agreements that limit the scopeof market between buyers and sellers.

7 Vertically integrated, investor-owned utilities accounted for nearly 80% of generated electricity as of 2000.8 According to FERC (n.d.), the designation of Independent System Operators grew out of Orders Nos. 888/889where the Commission suggested the concept of an Independent System Operator as one way for existing tightpower pools to satisfy the requirement of providing non-discriminatory access to transmission. Subsequently, inOrder No. 2000, the Commission encouraged the voluntary formation of Regional Transmission Organizations toadminister the transmission grid on a regional basis throughout North America (including Canada). Order No. 2000delineated twelve characteristics and functions that an entity must satisfy in order to become a RegionalTransmission Organization.


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22-5

Figure 22-2. Independent system operators and regional transmission organizationsof North America

Source: Energy Velocity

In addition to ISOs and RTOs, there are three other types of transmission organizations in theUnited States:

Traditional utilities that participate in ISOs/RTOs can also consist of utilities fromone or several states, and can have planning processes and market functions thatincorporate the RTO footprint

Traditional utilities that do not participate in an RTO, and have their own regionalplanning

Merchant transmission organizations that plan transmission and seek participants tohelp fund the transmission project.

The treatment of balancing authorities, regional entities, utilities and power pools, transmissionorganizations, interconnections, and other such aspects of the U.S. grid within RE Futures isdescribed in Chapter 28.


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23-1

Chapter 23. Utility System Planning

Utility system planning is a complex process that starts with projection or forecasting of demandfor electricity and develops alternative scenarios for the adequacy of generation resources andnecessary transmission and distribution system additions. This endeavor is especially complex

because the lives of the components and subsystems often exceed 40 years.

The roles and responsibilities for planning the future grid have evolved over the decades, andthey continue to change. Prior to industry restructuring in the 1990s, planning for futureinfrastructure investments was largely in the hands of the vertically integrated, investor-ownedutilities that planned both generation and the delivery system with cooperation among neighborsthrough the then-existing power pools or the large federal utility entities in the West and theTennessee Valley Authority in the East (Stoll 1989, Balu et al. 1991).

The Energy Policy Act of 1992 (EPACT 1992) required open access to transmission and createda new class of generators called exempt wholesale generators. Behind these changes was theintent to open competition in the electricity sector and permit wholesale customers to buy in acompetitive open market. FERC Orders 888 and 889 issued in 1996 started the regulatoryimplementation of the EPACT 1992, and significant restructuring of the industry resulted. Order888 fundamentally changed the dominant business model of the investor-owned utility industryby unbundling transmission services from the sale or marketing of electricity.

With these changes, the integrated utility planning process was fundamentally changed. Thefollowing decade saw a significant decline in transmission investment Orders 888 and 889created challenges to coordination of transmission and generation planning. Coordinatedplanning of transmission expansion and generation was the standard within the verticallyintegrated utility prior to restructuring, and was generally precluded by Order 888 as aconsequence of the resulting separation of transmission from generation in many regions (Hirst

and Kirby 2001).

The Energy Policy Act of 1992 and the diverse industry response across the various regionswithin the United States increased the diversity and complexity of utility planning. Wherewholesale markets and independent power producers are significant, the responsibility fortransmission planning largely rests with the RTO/ISO as does the procurement of generationresources. Where vertically integrated utilities continue, the process is still more complicated dueto the existence of exempt wholesale generators, open transmission access, and the FERC orders.

Using funds from the American Recovery and Reinvestment Act of 2009 (Recovery Act), theU.S. Department of Energy has initiated coordinated, interconnection-wide transmission

planning, with broad stakeholder input, and processes to feed these transmission plans back intodecision-making at all levels (Funding Opportunity Announcement, FOA #68).9 Thisinterconnection-wide planning activity is meant to facilitate development of robust transmission

9 The America Recovery and Reinvestment Act of 2009 directed the U.S. Department of Energy to provideassistance for the development of interconnection-wide transmission plans for the Eastern and WesternInterconnections, and for Texas (ERCOT).


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networks that can enable the use of new, clean energy generation and address the weaknessesthat exist in the grid.

In 2011, FERC issued Order 1000, Transmission Planning and Cost Allocation by TransmissionOwning and Operating Public Utilities, a continuation of Orders 888 and 890. This new ordercontains guiding language regarding how transmission planning cost allocation should occur.10This order is expected to result in greater emphasis on coordination of generation andtransmission planning and more cooperation among neighboring utilities.

A well-planned regional or interregional transmission system has many economic and reliabilitybenefits, which include but are not limited to improving load diversity, providing access tolower-cost remote generation, diversifying the resources portfolio (capacity and energy), sharingof resources and reserves among neighbors, enabling development of new resources and theirintegration, mitigating market power, and reducing price volatility. Reliability benefits includereduction of outages from multiple system contingencies and sharing of reserves, both of whichalso provide economic benefits. Transmission provides these benefits while accounting for lessthan 10% of the final delivered cost of electricity [total electricity retail sales revenue was $372billion in 2011 (EIA n.d.)]. In general, three transmission expansion-planning approaches are inuse:

1. Plan incremental transmission and generation additions to ensure system reliability

2. Plan incremental transmission and generation additions to ensure reliability and relievesystem congestion or constraints and improve economics

3. Plan a transmission overlay that would realize the broad benefits discussed in additionto allowing remote resources to reach all energy marketswithout adversely affectingunderlying AC transmission systems through appropriate upgrades.

The first two approaches generally look out 10 years or fewer. Many transmission organizationsrefer to their 10-year plans as long-term and adjust these long-term plans with near- orshort-term plans to account for recent system changes. These plans typically study incrementaltransmission additions, new generation, and load growth projections to address reliability and, insome cases, how to mitigate transmission system constraints and allow more economicoperation.11 The adoption of the third approach, which generally looks out 15 years to more than20 years, is a recent trend among utilities in transmission planning and signals a return to thelonger-term planning that was common before restructuring. The benefit of this approach is thatlong-term needs of the transmission system, in terms of capacity and corridor requirements, canbe identified by analyzing various scenarios and identifying common transmission needs in aproactive approach. This information can then be used in subsequent feasibility and detailedsystem studies that address reliability concerns, transmission system constraints, access tolowest-cost generation resources, and impacts to underlying systems. A combination of thesethree approaches is best employed to address the particular needs of the system being studied. Abottoms-up approach can address short-term reliability and constraint mitigation needs, and a

10 For the complete Order 1000 text, seehttp://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdf.11 Constraints (also referred to as congestion) are a condition of the transmission system in which the transmissionline loading has met the operating limit criteria for which it was designed. It is a problem to the extent that lower-cost resources are prevented from reaching higher-priced markets.
http://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdfhttp://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdfhttp://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdfhttp://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdf


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top-down, value-based12approach might best address the systems long-term reliability andeconomic needs.

Short-term studies may work well in some applications, but they may not adequately identify thelonger-term (20-year and beyond) needs of the transmission system. Reliance on the short-termapproach may lead to sub-optimization of the bulk electric system over time (e.g., inadequatetransmission capacity and voltage selected). For example, in the short term, a lower-voltage andless expensive line addition may be adequate but may require an expensive upgrade within adecade; in contrast, an initially more expensive and higher-capacity line might be less expensivein the long term. Short study periods and their potential sub-optimizationgiven the 4060-year(or more, in many cases) in-service life of transmission linesmay limit the possibility ofconstructing higher-efficiency multiple-line systems and identifying underlying system upgradesto fully realize the reliability and economic benefits a robust transmission system provides.

As states and federal agencies work to implement new energy policies, the process of utilityplanning will continue to change and evolve. New and emerging technologies discussed inSection 26.1 offer new technical solutions, and new institutional arrangements may facilitatetheir adoption. Barriers to institutional innovation may also bar adoption of new technologicalsolutions. The cooperation being promoted by the interconnection-wide planning activities of theRecovery Act as well as the new FERC Order 1000 may be critical elements to utility planning.

12 A value-based approach seeks to quantify the cost of outages and balance it with the cost of infrastructure to avoidor minimize the costs of outages to customers. 13 All planning must meet NERC standards as shown on its website athttp://www.nerc.com/page.php?cid=2|20.
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Chapter 24. Grid Reliability

As discussed in Chapter 22, electricity production and demand must be dynamically balanced atall times. Achieving this balance is a challenge for the planning, 13engineering, and operation ofthe power systems because of variability and uncertainty of load and unexpected equipment

failures that affect the generation and delivery of electricity. Maintaining this dynamic balanceand the significant consequences of failure to do so is a fundamental challenge. Many elementscontribute to the operability of an electric power system at many scales, from purely local toregional. Local reliability issues can range from a small electrical disturbance that lasts from afraction of a second to a few minutes, or a more extended interruption of electric supply as aconsequence of a local event such as a tree falling across a power line a few blocks away due tosevere weather. The consequences can range from a loss of power quality to an outage that canlast from hours to days.

NERC defines electric system reliability as the ability to meet the electricity needs of end-usecustomers, even when unexpected equipment failures or other factors reduce the amount of

available electricity (NERC n.d.). Maintaining reliability involves ensuring that adequateresources are available to provide customers with a continuous supply of electricity as well ashaving the ability to withstand sudden, unexpected disturbances to the electric system (NERCn.d.). NERC describes power system reliability more completely in terms of electric systemadequacy and security.

Adequacy is the ability of an electric system to supply the aggregate electricaldemand and energy requirements ofthe end-use customers at all times, taking intoaccount scheduled and reasonably14 expected unscheduled outages of systemelements (NERC n.d.).

System securityoroperating reliability is the ability of an electric system to

withstand sudden disturbances such as electric short circuits or unanticipated loss ofpower system element(s) such as a power plant or a transmission line (NERC n.d.).

Thestability of the grid is the ability of an electric power system to maintain a state ofequilibrium between generation and demand during normal and abnormal conditions ordisturbances. If the system becomes unstable, it may experience a collapse of system voltageand, as a consequence, protective equipment may open circuit breakers and disconnect areasfrom the interconnection, in hopes of keeping smaller areas within operational limits andsubsequently causing the interconnection to break into pieces as it did in the August 2003blackout.

Power systems are planned and operated so that a credible disturbance, event, equipment failure,

or other contingency will not cause any area of an interconnection to be operated outside ofspecified voltage and frequency and not cause generation or transmission equipment to operate

13 All planning must meet NERC standards as shown on its website athttp://www.nerc.com/page.php?cid=2|20.14 The question of what are reasonable contingencies to examine is a very complex one. The complexity increasesgreatly as the number of simultaneous contingencies increases. If there are N elements in the system, contingenciesare referred to as N-1 (Class B), N-2 (Class C and D), etc. Very-large-scale blackouts are often preceded by an N-3contingency.
http://www.nerc.com/page.php?cid=2|20http://www.nerc.com/page.php?cid=2|20http://www.nerc.com/page.php?cid=2|20http://www.nerc.com/page.php?cid=2|20


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outside normal limits. The participants in the grid follow rules and principles to ensure reliabilityfor planning and operating the interconnections; these criteria form the basis for reliabilitystandards (NERC 2012).

A complete analysis of power system reliability comprises the following:

System adequacy: To fully understand overall system adequacy, Monte Carlosimulations are generally required to measure LOLP with the appropriate probabilitydensity functions of various power system variables. Many scenarios would need tobe analyzed to understand whether the overall electric system has adequate systemcapacity to meet load under a variety of operating conditions. With conventionalgeneration units, this type of study typically involves running reliability models usingthe forced outage rate and mean time to repair for the full suite of units, while alsoconsidering possible changes in electricity demand, to estimate the LOLP. With highamounts of variable generation, analyses of this type become somewhat more difficultdue to the unique behavior of variable generation.

High-resolution production modeling: In most electricity systems today, loadchanges in somewhat regular patterns from one hour to the next, and within eachhour. Load typically increases during the morning period and falls off in the evening.With high levels of variable renewable generation, however, net load15 may varymore irregularly and on shorter time frames. Running simulations at sub-hourly levelsor even at sub-minute levels may be needed to fully understand the impacts of thesechanges in net load and to assess the quantity of reserves needed to managevariability and forecast errors that occur within the hour.

AC analysis: Many power system models use what is called a direct current (DC)power flow assumption, which approximates how power flows on the system in orderto readily solve optimization problems. In practice, this means that the voltage of the

system is ignored, reactive power flows on the system are ignored, and line losses areapproximated. A full AC analysis can more accurately estimate power flows on thesystem and address these concerns. In RE Futures, while GridView provided DCpower flow analysis, a full AC analysis was not done.

Power system stability studies: Stability is a condition of equilibrium betweenopposing forces, and maintaining power system stability is essential to ensuring areliable electricity system.Rotor angle stability refers to maintaining synchronismbetween synchronous machinesthese are primarily the large-scale power generationunits in central station power plants. Small signal stability refers to maintainingsynchronism following small disturbances, and transient stability refers to

maintaining synchronism following severe disturbances. A variety of studies arenecessary to address these aspects of power system stability, including analyses ofsynchronism during transmission system faults as well as other studies that evaluatefrequency response during loss-of-supply events. As one example of the issues inquestion, many variable renewable generators cannot currently respond to system-

15 Net load is calculated by subtracting all forms of variable generation from the native load. The net load is whatmust be managed by the remainder of the power system, assuming all variable generation can be used whenavailable.


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wide frequency deviations with off-the-shelf technology, and analyses are thereforeneeded to assess (1) future electricity systems where substantial amounts ofgeneration do not have frequency response capabilities as well as (2) newtechnologies that might be used to manage those possible deficiencies. Voltagestability, meanwhile, refers to maintaining steady and acceptable voltages at all buses

(major points of connection) in the system under both normal conditions andfollowing disturbances. Regardless of the specific aspect of system stability underconsideration, stability studies require very high time-resolution analysis, usually atthe hundredths-of-a-second timescale but for only the first few seconds followingdisturbances.

Contingency analysis: Power systems are typically designed for high reliability andtherefore need to be secure following severe but credible contingency events. Realpower systems are operated with various contingencies in mind, and carefulconsideration is required to determine which contingencies should be monitored andhow the system should operate to maintain a stable system following contingencyevents. Analysis of such issues usually includes determining those contingencies that

are most likely based on historical evidence as well as those that are most severe,based on contingency screening. The complexity of contingency analysis generallyincreases with the dimension (i.e., number of nodes and connecting lines) of thesystem or region being considered and the number of simultaneous events involved.

In RE Futures, the grid reliability analyses described above have not been done. However, themodeling tools employed in the study required adequate reserves to be available, in some casesbased on statistical proxies (see Chapter 28 for more information).

24.1 Planning Reserves (Reserve Margin)A key step in addressing operating reliability and ensuring system adequacy is determining theneeded generation capacity that must be installed to meet future demand. Additional capacity

above and beyond the expected peak load is needed so that sufficient resources are available atall times to meet load. This additional margin is calledplanning reserves. Historically, planningreserves have been defined and calculated as a percentage of peak demand (load) and can varyby utility and/or region. Typical traditional values for planning reserve margin range from 12%15% of annual peak load. Dispatchable generators contribute name-plate capacity towardplanning reserves.

After the demand has been forecasted for a given time horizon, generation expansion or relatedmodels are used to assess system adequacy (i.e., to determine whether there is sufficientgeneration to meet the future load). Additional capacity is needed to cover possible generationoutages or peak load forecasting error. Because of the stochastic nature of generator outages,

robust probabilistic methods are used to assess generation adequacy. Models that calculate loss-of-load probability (LOLP) or related metrics such as loss-of-load expectation (LOLE) can beused to assess the probability that there is insufficient generation to cover loads. A typical LOLEtarget is that there would only be a shortage for 1 day in 10 years (see Figure 24-1).

The effective load-carrying capability (ELCC) is a measure of the additional load that can besupplied after adding new generation, holding the LOLE constant. The ELCC approachcalculates LOLP over all hours of the year (multiple years are recommended). Times of high


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LOLP are relatively few and typically occur during peak or near-peak periods. This approachexplicitly quantifies and holds constant the risk of having insufficient native generation to coverload. The ELCC approach is robust across all technologies; in particular, it can be applied to bothconventional and variable generation technologies.16 In modern interconnected systems, LOLPand LOLE measure the likelihood that imports will be necessary to meet load during high-risk

periods.

Figure 24-1 shows the relationship between LOLE and load. At the presumed target adequacylevel of 1 day in 10 years, if new generation is added, the curve shifts to the right. Holding thereliability target constant, the horizontal difference between the curves is the ELCC of the newgenerator.

Figure 24-1. Examples of reliability curves to illustrate effective load-carrying capability

Source: Milligan and Porter 2008

16The ELCC method is recommended by the IEEE Task Force on Wind Capacity Value (Keane et al. 2011).


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Chapter 25. Power System Operations

Power systems operational procedures can generally be divided by timeframe, as depicted inFigure 25-1. A balance between total customer demand and total system generation needs to bemaintained essentially instantaneously at all times. The balancing process is carried out in

several different time frames. Generating units are typically committed to operation a day inadvance to cover the forecasted load profile for that day plus a reserve margin. Scheduling (oreconomic dispatch) of plant output levels is then carried out generally on an hour-by-hour basis.Some plants are designated to follow load variations within the hour, and other plants provideregulation service to balance instantaneous load variations in the seconds-to-minutes timeframe.

Figure 25-1. Timescales for power system operation

The figure is illustrative and not to scale. The notch at 1819 hours represents asecondary peak that occurs in some regions in early weekday evenings as commercialload drops off and residential loads ramp up.

This section discusses several elements of power system operations, including forecasting andthe day-ahead schedule or unit commitment, within-a-day economic dispatch, frequencyresponse and control, and operating reserves. These functions are initially described in theabsence of variable generation. Later sections discuss the impact of large-scale variablegeneration on each of these operational timeframes.


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25.1 Security-Constrained Unit CommitmentUnit commitment is a process of determining which generating units will be needed for thefollowing day, and ensuring that any needed large thermal units are started and synchronized tothe grid. This process is based on day-ahead load forecasts, and is necessary because many largethermal units take many hours to reach operating temperature before generating energy. Typical

load forecast accuracy depends on many factors, including the size and characteristics of thesystem itself. Generally, however, a typical error of a day-ahead load forecast is about 2%3% ofthe peak load. A typical schedule is planned hourly for the next 2448 hours, depending onoperating practice at the balancing authority. The unit commitment process aims for aneconomically efficient solution, given the various physical and institutional constraints involved.Because the future is uncertain, there is some risk that either too much or too little capacity iscommitted, resulting in challenges during the operating day. To help mitigate this risk, the powersystem operator will commit an additional level of capacity, operating reserves, which can becalled upon if load forecasts are in error or if there is an equipment failure. The cost of over-commitment can be significant because some generation may be forced to run at inefficientoutput levels, or even curtailed. Similarly, the cost of under-commitment can be significant if

expensive peaking units must be started to meet load that could have been met by less expensivethermal units. However, the consequences of unit commitment errors vary widely based onsystem characteristics.

In most electricity markets and utility operator balancing authorities in the United States, the unitcommitment process and schedule are generally established once a day, with schedules due mid-day on the day prior to the operating day.

25.1.1 Operating ReservesPower system operators ensure that there is available generation capability above that which isscheduled for energy, or operating reserves that can respond to the inherent variability in loadand unforeseen events such as the sudden failure of a key transmission line or generator. These

reserves can be broadly defined as event-based reserves ornon-event-based reserves. Acomplete discussion is beyond the scope of this report, but details can be found in Ela et al.(2010).

17When units are committed for day-ahead, sufficient operating reserves must be a part

of the determination of the unit commitment stack.

Contingency reserves18

are used in the event of sudden generator or transmission failure. Thebalancing authority carries sufficient reserves to cover the loss of the largest contingency,although variations on this are possible. In addition, the proliferation of reserve-sharing groupshas allowed sharing of the contingency reserve burden across multiple balancing authoritieswithin the same interconnection, and subject to transmission constraints.

A contingency event occurs very suddenlywithin a cyclewhen a unit trips or a line opens.Several types of reserve come in to play after the contingency occurs so that the activatedreserves can be replaced in case another contingency event occurs.

17 Milligan et al. 2010 provides an international context for operating reserves.18 Contingency reserves are used to balance resources and load and return interconnection frequency to withindefined limits following a reportable disturbance (a loss of power system element). Contingency reserves can be amix of spinning, non-spinning, and interruptible load according to requirements established by the balancingauthority and reserve-sharing group.


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Non-events include the normal operation ofthe power system. Reserves in this category includeregulating reserve, a capacity-only service,

19which is used to manage short-term fluctuations in

demand that occur continuously, and load-following reserve (Ela et al. 2011), which at present isnot a well-defined product but includes an energy component and occurs over time periods fromseveral minutes to a few hours. Reserves can be separated into categories based on required

response time.Fast reserves generally must be available within 10 minutes, whereas a slowerresponse may be required for load-following or replacement reserves.

The only specific reserve that is required by NERC is contingency reserve; however, thebalancing authoritys ability to meet its required balancing standards (control-performancestandards) results from holding regulating reserves and other balancing reserves. Because thesereserves are required in the operating timeframe, they are often referred to as operating reserves,which distinguishes them from planning reserves. There are many variations in terminologyregionally and internationally. Some reserve types can be split between spinning (i.e., committedand synchronized) and non-spinning (i.e., capable of connecting and synchronizing within aprescribed time period, typically 10 minutes). Regulating and frequency-control reserves, bytheir nature, must be entirely spinning, whereas other reserves can consist of a combination ofspinning and non-spinning reserve.

If a large thermal generator is suddenly lost, the instantaneous impact of such a loss to thesurrounding power system and system operating reserves requirements is depicted in Figure25-2. Turbine speed governors and the systems automatic generation control (AGC) sense adrop in system frequency and initiate corrective action to increase power from generators that arestill operating.

Figure 25-2. Example conventional generator contingency event and response

Source: Ela et al. 2011

19 A regulating unit sometimes provides energy and sometimes absorbs energy on a second-to-second basis tomaintain instantaneous system balance. On average, essentially no energy is provided to the power system byregulating units


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25.2 Economic Dispatch and Load FollowingDuring the operating day, in addition to the generation already committed to serving load, thesystem operator has quick-start generation on reserve to help cover unexpected changes indemand or contingencies and may have access to electricity markets that can provide additionalgeneration. These sources of energy may be used to meet both the anticipated changes in energy

demand throughout the day, and any unanticipated changes in demand.

The load-following timeframe generally refers to time steps from tens of minutes to a few hours.Load swings are matched by changing generation schedules. These changes are accomplished byadjusting, or dispatching, generating units to minimize the economic cost of meeting demand,subject to their physical characteristics. This process is called economic dispatch.

Regions of the United States that participate in large wholesale energy markets, such as MidwestISO (MISO) and PJM, typically perform the economic dispatch sub-hourlyin increments of 5minutes. This means that any generator that is capable of respondingboth in its physical andeconomic capabilitiesis available to help manage the variability inherent in the power system.In most regions of the Western Interconnection, the economic dispatch function is performedonce an hour. This practice places an artificial restriction on generation that is technicallycapable of responding to variability; there is no institutional mechanism that allows such units torespond, even if economic.

25.3 Frequency Response and ControlFrequency control (60 Hz) is the basis for several reliability metrics. The deviation of linefrequency from its nominal value of 60 Hz is the first indicator of a problem in the powersystem, and, in general, the larger the deviation, the bigger the problem. The problem typicallybegins with the sudden failure of a large conventional generating plant or the loss of transmissioncapacity, resulting in too little power generated and transmitted to fully meet the load. This

generally causes the frequency to drop from its 60-Hz value (see Figure 25-2) as largeelectromechanical generators, motors, and other equipment slow. In correcting this, many factorsinfluence the frequency response and control of the power system. Balancing and frequencycontrol occur over a continuum of time using different resources. Frequency response begins tostabilize the system frequency within the first few seconds following a disturbance. Abnormalfrequencies can damage power system equipment, especially large steam turbines. Frequencyresponse from generators actually helps protect the turbines from exposure to abnormalfrequencies by limiting the magnitude of the frequency change during events. As moregenerators participate in frequency response, overall frequency response will increase within theinterconnection and the abnormal frequency deviation will be reduced.


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Chapter 26. Transmission Technology and Institutional Issues

The design and engineering of the transmission system is affected by both technical andinstitutional issuesbusiness, regulatory, and political. This chapter provides a brief overview oftransmission technology and then an introduction to the basic institutional issues.

Casazza (1993) documents the drivers and benefits of the expansion of transmission systemsover the decades and the development of todays interregional grid that spans North America.The value of transmission comes from many sources of savings, such as:

Delivering electricity from lower-cost remote resources

Sharing large low-cost generation among systems

Reducing the need for both planning and operating reserves

Allowing production of electricity from the lowest-cost supplies at all times

Taking advantage of seasonal, weekly, and hourly load diversity among systems

Making remote hydropower and mine-mouth20 coal plants available to more users

Permitting surplus hydropower generation in one system to be used in another.

Today, this list can be expanded to include more economic operation of large regional wholesalemarkets, access to higher quality, lower-cost remote renewable generation, and reducingvariability and uncertainty of variable renewable generation over a large geographical region.

As identified in the National Interest Electric Transmission Corridors and Congestion Study(DOE 2009), there would be general economic benefit from strengthening the transmissionsystem; however, the relationship between this general economic benefit and the private return to

companies paying for new transmission is often insufficient or too uncertain to spur investment.New transmission could address the general increase seen in grid congestion and support thecreation of broader markets for electricity, as well as support the future integration of renewableresources.

26.1 Transmission TechnologyThe highest operating voltage transmission lines in the United States, which operate at a nominal765 kV, came into service in the 1970s. Worldwide, the transmission technologies in use andfunctioning today, either broadly or in initial installations, for transmitting bulk electrical powerare high, extra-high, and ultra-high-voltage AC transmission systems up to 1,000 kV (GlobalTransmission 2009); high and ultra-high-voltage DC transmission systems; and undergroundcables (e.g., solid dielectric and gas-insulated). All of these technologies have unique applicationcharacteristics, as discussed in the following sections.

This brief overview of basic transmission technology provides a backdrop for understanding theright-of-way requirements for the siting and permitting of transmission lines. The transfer oflarge amounts of electricity within and among regions can provide economic benefits as

20 Mine-mouth refers to a generating station located at a coal mine in order to be close to the fuel source instead oftransporting the coal to the generating facility.


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discussed previously, but those benefits can be limited by institutional barriers to expansion ofthe transmission system. The current motivation for pursuing new higher capacity transmissiontechnology is the growth of large regional markets and the opportunity for greater economicexchange. The future value for this technology may include enabling the transfer of renewableenergy from more remote locations, where the higher-quality and lower-cost resources are

available to serve load centers, and continuing to support the trend of wider area operationalcoordination, which can reduce the variability and uncertainty of variable renewable generation.

26.1.1 Alternating Current Transmission SystemsThe majority of transmission systems in the United States and worldwide are conventional AClines. In the United States, these are often referred to as high-voltage (up to 345 kV) and extra-high-voltage (above 345 kV to 765kV). Over the decades since AC technology was firstdeveloped, transmission voltages steadily increased as the technology of the grid improved.Higher voltages result in lower losses and higher capacity for a given right-of-way. Highervoltages require greater distances between the wires or conductors as well as better and longerinsulators and higher towers, but the net effect is still a significant increase in the power transfercapability for a given width of right-of-way, and higher voltages are preferred for longerdistances and larger transfer capacity. Figure 26-2 provides an artist representation of the spacerequirements for different levels of voltage. Although the highest voltage transmission lines inuse in North America are 765-kV AC, transmission voltages continue to increase worldwide.

26.1.2 High-Voltage Direct Current Transmission SystemsHigh-voltage direct current (HVDC) is occasionally used for very long distance or very highcapacity lines. HVDC lines cost less than overhead high-voltage AC lines of the same voltageand have lower operating losses. However, HVDC convertor stations, located at each terminal ofthe line, cost significantly more than AC substations. Figure 26-1 shows the relative cost ofextra-high-voltage AC versus 800-kV DC forconstructing a transmission line to transmit 6,000MW over various distances at 75% utilization.21 In general, the 765-kV AC, 500-kV HVDC, and

800-kV HVDC systems appear to be the best options. These general performance indicators aresubject to project-specific requirements. When performing transmission system expansionplanning studies, these project-specific requirementsspecifically distance and loadingwouldbe analyzed to determine the optimal transmission technology to meet the project need.

21 Transmission line and substation costs are based on Frontier Line Transmission Subcommittee, NorthwestTransmission Assessment Committee (NTAC), and ERCOT Competitive Renewable Energy Zones (CREZ) unitcost data.


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Figure 26-1. Comparison of costs to deliver 6,000 MW over various distances and voltages at75% utilization

Source: Bahrman 2009

Series Comp refers to series compensated AC lines where capacitance is added tobalance the inductance of the overhead transmission line as transmission distanceincreases.

An economic analysis that takes into account capital costsincluding converter stations, line

lengths, voltage levels, and power transfer capabilitywould be considered to determine the

most economical transmission solution. In general, the break-even point for deciding to use a DC

system instead of an AC system for a transmission project (not considering such factors asmultiple converter stations and changes in operating voltages over time) is in the vicinity of 300

to 600 miles for overhead lines.

DC transmission systems have significant benefits when transmitting large amounts of power

long distances and can do so between two asynchronous AC systems. Additional benefitsinclude, but are not limited to, power flow control and enhanced system stability. For example,

the high-capacity contingency rating of an HVDC overlay could accommodate the loss of a large

conventional generator and be stable. Regarding land use, DC transmission systems require lessright-of-way for similar amounts of transfer capability (see Figure 26-2).


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Figure 26-2. Comparison of general right-of-way requirements for various transmission types

Right-of-way is a term that can have different meanings. As used in this volume, it meansthe path taken by a transmission line and the property impacted by that transmission line.It can also imply an easement or right to reasonable use of the property over which thetransmission line runs. The owner of the transmission line may own the property or have

an easement or rights for its use.


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26.1.3 Higher VoltagesAlthough the highest voltage transmission lines in use in North America are 765-kV AC,transmission voltages continue to increase worldwide.22 As shown in Table 26-1, both 1,000-kVAC and DC lines are being constructed in China.

Table 26-1. Ongoing Ultra-High-Voltage Projects in China, 2009

Location Technology Capacity Distance

Jindongnan-Nanyang-Jingmen Ultra-High-Voltage AC, 1,000KV 6,000 MW 654 km

Yunnan-Guangdong Ultra-High-Voltage DC, 800KV

12 pulses, bipole

5,000 MW 1,438 km

Xianjiaba-Shanghai Ultra-High-Voltage DC, 800KV

12 pulses, bipole

6,400 MW 1,907 km

Source: Li 2009

The advantage of using higher voltages is the decline in per unit costs; the disadvantage is therisk of losing a larger portion of transmission capacity in a single contingency failure. Moredetailed studies will be needed to conceptualize, design, and evaluate the merits for a high-voltage overlay.

26.1.4 Superconducting CablesWhen long-distance overhead transmission lines approach major population and load centers, theavailability of right-of-way for overhead lines can become limited. Similarly, overhead lines maybe undesirable in environmentally sensitive areas. Political and institutional issues cancompletely block construction of an overhead line. New high-temperature, superconductor-basedtransmission cable technology may offer an alternative in the longer term, not just for shortdistances in urban areas but also for long-distance transmission (EPRI 2009) where pipe-enclosed DC superconducting transmission cables can either be buried underground or placed in

tunnels. These cables use high-temperature superconductor materials instead of copper oraluminum and have substantially higher power handling capabilities at lower voltages thanconventional cables. This additional power-carrying capacity allows this technology to addressreliability concerns associated with long-term load growth in densely populated urban areas.When operating in DC systems, these cables exhibit zero resistance, hence zero electrical losses;however, there are parasitic refrigeration losses. The commercial competitiveness remains to befully demonstrated in the market. As this technology is not commercial, it was not included inRE Futures transmission modeling.

Regarding right-of-way, the superconductor electricity pipeline (EPRI 2009) requires little landand it can be buried, which offers potential benefits to siting and security (Reddy 2010).

22 ABB (n.d.a); ABB (n.d.b); ABB (n.d.c)


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26.2 Transmission and Institutional IssuesInstitutional issues related to transmission include jurisdictional complexity, permitting, sitingand right-of-way acquisition, and cost allocation and cost recovery, among others. 23

26.2.1 State and Federal JurisdictionsAlthough the Federal Power Act puts interstate transmission rates under the jurisdiction ofFERC, the regulatory and economic drivers affecting transmission planning are split among thefederal government and the states. Retail electricity rates are set locally by state public utilitycommissions, cities (in the case of municipally owned utilities), or customer-elected boards (inthe case of rural electric cooperatives). The cost of new generation (such as that from a newthermal plant, new wind power, or power purchased from merchant generators) is recoveredthrough retail rates.

26.2.2 Siting, Permitting, and Right-of-Way AcquisitionCurrently, the siting and permitting of transmission lines is the responsibility of individual states.A line serving utilities in more than one state or one connecting across several states would bestbe planned, sited, and permitted in a process coordinated across all involved jurisdictions.However, multi-state regulatory coordination is rare and, where federal legislation has notclarified the situation, can be problematic. Authority for regulation of interstate commerce restswith Congress. Currently, federal regulatory authority over interstate transmission lines is limitedto those situations where the U.S. Department of Energy has declared a possible corridor as oneof national interest, and there is not yet experience with these recent provisions of law, whichmakes the development of an interstate transmission line higher risk than the development of aline situated completely within one state. State policy may also create a preference for in-stateresources, which would require shorter lines from local resources, but may not permit capturingthe benefits of integrating generation across a larger geographic area encompassing severalstates.

24

A transmission plan may seem to be technically feasible after power flow and production costmodeling, but can be legally or economically infeasible when attempting to select a specificroute for a line. Siting issues that commonly delay transmission permitting include opposition byindividual landowners or community groups to the location of the facilities; opposition to theexercise of eminent domain for easements across property; concerns over property values; andenvironmental concerns regarding endangered species and habitat and aesthetics.

23 A white paper summarizing issues affecting siting transmission corridors is available from The National ElectricalManufacturers Association athttp://www.nema.org/gov/upload/tC_gameboard_verticle.pdf.24 Section 216(a) of the Federal Power Act (created by section 1221(a) of the Energy Policy Act of

2005) directs DOE to identify transmission congestion and constraint problems. In addition, section 216(a)authorizes the Secretary, in his discretion, to designate geographic areas where transmission congestion orconstraints adversely affect consumers as National Interest Electric Transmission Corridors (National Corridors).A National Corridor designation itself does not preempt State authority or any State actions. The designation doesnot constitute a determination that transmission must, or even should, be built; it is not a proposal to build atransmission facility and it does not direct anyone to make a proposal to build additional transmission facilities.Furthermore, a National Corridor is not a siting decision, nor does it dictate the route of a proposed transmissionproject. The National Corridor designation serves to spotlight the congestion or constraint problems adverselyaffecting consumers in the area and under certain circumstances could provide FERC with limited siting authoritypursuant to FPA 216(b) (DOE 2009).
http://www.nema.org/gov/upload/tC_gameboard_verticle.pdfhttp://www.nema.org/gov/upload/tC_gameboard_verticle.pdfhttp://www.nema.org/gov/upload/tC_gameboard_verticle.pdfhttp://www.nema.org/gov/upload/tC_gameboard_verticle.pdf


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Siting is especially complicated when a major transmission project spans several states. Filingrequirements, timelines, and even the type of authority vary by state according to statute. In somestates, a single agency conducts centralized (one-stop) review and approval; in other states,each county conducts its own review and approval. Consequently, a transmission developer mayface several litigation actions (each with different issues and evidentiary needs) for one major

project.

A state can exercise eminent domain to obtain an easement on behalf of a utility but, in manycases, the utility can obtain landowner consent by offering financial incentives that are slightlymore lucrative. However, regulators recognize that having eminent domain as an optiongenerally provides landowners a stronger incentive to accept negotiated compensation becausethe condemnation value awarded under eminent domain would almost always be less.

The assessment of environmental impacts is an especially common transmission siting issue. In2008 and 2009, the Western Governors Association worked with environmentalnongovernmental organizations and other stakeholders to identify high-quality wind, solar, andgeothermal development areas that had the least impact on sensitive habitats. Although notcompleted, this work contributed to progress toward the identification of Western RenewableEnergy Zones (Western Governors Association 2009).

Some siting and permitting issues occur at the federal level, particularly when part of atransmission line crosses federally owned land or areas that enjoy protection under federal law.Any proposed development on federal lands requires review under the National EnvironmentalProtection Act, a process that can be lengthy. However, during the past few years, the U.S.Department of Interior has begun to implement programmatic environmental impact statementprocedures for wind, solar, geothermal, and transmission projects. This is an effort to streamlinethe federal permit review by addressing issues that are not site-specific.

The Energy Policy Act of 2005 (EPAct 2005) gave FERC limited backstop siting authority.FERCs current authority is limited to national interest electric transmission corridors (alsoestablished by EPAct 2005), and recent court rulings have established that FERCs backstopauthority only applies if a state siting authority fails to act in a timely manner. The court struckdown FERCs ability to overturn a state siting decision that was rendered in a timely manner.


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26.2.3 Transmission Cost AllocationTransmission cost allocation is controversial and one of the most important issues to resolve ifsignificant transmission system expansion is to be realized.

Cost allocation25 refers to how costs for new transmission are divided among different users and

customers. The term implicitly includes discussion of the mechanisms by which costs arerecovered. Cost allocation often raises equity issues because customers and regulators in onestate may object to paying for benefits that accrue to customers in another state. Most cost-allocation conflicts ha

Renewable Electricity Futures Study-4

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